Large quantities of extractable hydrocarbons exist in subsurface shale formations and other low-permeability strata, such as the Monterey Formation in the United States and the Bakken Formation in the United States and Canada. However, extraction of hydrocarbons from certain low-permeability strata at commercially useful rates has proven to be a challenge from technical, economic and environmental perspectives. One approach for extracting hydrocarbons from shale and other low permeability rocks has been to induce the formation of large scale massive fractures through the use of an elevated hydraulic pressure acting on a fluid in contact with the rock through a wellbore. However, this is often accompanied by serious environmental consequences such as a large surface “footprint” for the necessary supplies and equipment, as well as relatively high costs. As well, concerns have been expressed regarding the potential environmental impact from the use of synthetic additives in hydraulic fracturing solutions. These financial and other factors have resulted in difficulties in commercial hydrocarbon extraction from shale oil beds and other low permeability strata. In general, conventional hydraulic fracturing or “fracking” methods generate new fractures or networks of fractures in the rock on a massive scale, and do not take significant advantage of the pre-existing networks of naturally occurring fractures and incipient fractures that typically exist in shale formations.
A typical shale formation or other low-permeability reservoir rock comprises the matrix rock intersected by a network of low conductivity native or natural fractures 10 and fully closed incipient fractures 12 extending throughout the formation, as depicted in FIG. 1. FIG. 1 is a two-dimensional depiction of a three-dimensional fracture network in a rock mass with a low-permeability matrix. It is understood that in reality there are many three-dimensional effects, and that the rock mass is acted upon by three orthogonally oriented principal compressive stresses, but in FIG. 1 only the maximum and the minimum far-field compressive stresses—σHMAX 14 and σhmin 16 respectively, acting in the cross-section are represented. The natural fractures 10 and planes of weakness typically exist in a highly networked configuration with intersections between the fractures, and usually but not always with certain directions having more fractures than others, depending on past geological processes. In their natural state, some of the fractures may be open to permit flow, but in most cases require stimulation. The majority of fractures are almost fully closed or are not yet fully formed fractures. These are “incipient” fractures which can be turned into open fractures by appropriate stimulation treatments during injection. The relative stiffness and the geological history of the rock engenders the natural formation of the network of actual and incipient fractures. The natural fractures 10 are mostly closed as a result of the elevated compressive stresses acting on the rock as depicted in FIG. 1, and because the rock mass has not been subjected to any bending or other deformation. In their closed state, fractures provide little in the way of a pathway for oil, gas or water to flow towards a production well. When closed, fractures do not serve a particularly useful role in the extraction of hydrocarbons or thermal energy.
In prior art fracture processes, sometimes referred to as “high rate fracturing” or “frac-n-pack”, a fracture fluid which usually comprises a granular proppant and a carrying fluid, often of high viscosity, is injected “wellbore” 18 into the injection well 19 at a high rate, for example in the range of 15-20 or more barrels per minute bpm. As depicted in FIGS. 2 and 3, this process tends to generate relatively fat fractures that propagate outwardly from the wellbore 18 of the injection well 19. In a typical sandstone reservoir, the process creates a dominantly bi-directional fracture orientation with the major induced fractures oriented at ˜90° to the smallest stress in the earth, depicted as the primary fractures 20 FIG. 2. Secondary fractures 22 may form to a limited extent, as seen in FIG. 2. The fluid generating the fracture is gradually dissipated across the walls of the fracture planes in the direction of the maximum pressure gradient as fracture fluid down-gradient leak-off 24 (FIG. 2). In prior art high proppant concentration methods employing viscous fluids with extremely high contents of granular proppant (FIG. 3), said proppant also tends to be forced between the wellbore 18 and the rock 21 under a high hydraulic fracture rate, to create a zone 23 of proppant fully or substantially fully surrounding the injection well 19. This provides good contact with the induced fractures 11 and connecting with the primary 20 and secondary 22 fractures emanating from the region of the wellbore 18 (FIG. 2). The large size of the hydraulic fracture wings 28 interacts with the natural stress fields 30 FIG. 2 so that it is necessary to inject at a pressure substantially above the minimum far-field compressive stresses σhmin 14 (FIGS. 1 and 2), and in prior art it has been described as necessary to co-inject a relatively large amount of proppant suspended within the viscous fluid to maintain the induced fractures 11 in an open and permeable state once the high injection pressures are ceased. The fracture patterns which result from at least some prior art processes are characterized by a relatively limited bi-directional fracture orientation, with relatively poor volumetric fracture sweep because of a limited number of fracture arms. The efficiency of interaction between the created fractures and the natural fracture flow system within the formation is believed to be low in such cases, and the lowest efficiency is associated with hydraulically induced fractures 11 of thin aperture and consisting only of two laterally opposed wings with no secondary fractures.
In certain prior art fracturing processes, liquids are deliberately made more viscous through the use of gels, polymers and other additives so that the proppants can be carried far into the fractures, both vertically and horizontally. Furthermore, in said prior art fracturing, extremely fine-grained particulate material may be added to the viscous carrier fluid to further block the porosity and reduce the rate of fluid leak off to the formation so that the fracture fluids can carry the proppant farther into the induced fracture. Prior art fracturing is typically designed as a continuous process with no interruptions in injection and no pressure decay or pressure build-up tests i.e., PFOT, SRT carried out within the process to evaluate the stimulation effects upon the natural fracture 10 network or the flow nature of the generated interconnected extensive fracture network. Prior art fracturing processes typically do not shut down, and in some realizations, increase the proppant concentration in a deliberate process intended to create short fat fractures.